Legacy Reserves LP ("Legacy") (NASDAQ:LGCY) today announced second
quarter results for 2016 including the following Q2 highlights:
- Reduced lease operating expenses, excluding ad valorem taxes,
to $41.5 million representing an 11% decrease compared to Q1 2016
and a 14% decrease compared to Q4 2015
- Maintained production of 44,615 Boe/d, a 2% reduction compared
to both Q1 2016 and Q4 2015 (without adjusting prior periods for
recent asset sales)
- Closed an additional $19.0 million of asset sales
- Further reduced debt outstanding by $67.6 million including a
$37.0 million reduction in borrowings under our credit facility and
$30.6 million of repurchases and exchanges of senior notes
Operational Update
Through Q2 2016, we spent $11.7 million of our $37
million 2016 capital budget representing a year to date spend of
32% of the budgeted total. Approximately 22% was spent on
recompletions and workovers in our East Texas region. The majority
of the balance was deployed in the Permian on workovers and on
horizontal development under our development agreement with an
affiliate of TPG Special Situations Partners (“TSSP”) under which
we operate all wells and fund 5% of the parties' development
capital. Since September 2015 we have drilled and completed 12
horizontal wells under the program: 5 in Lea County, NM, 1 in
Southern Reagan County, TX and 6 in Howard County, TX. After 6
months of inactivity, we recently resumed horizontal development
and currently have two rigs running, one in Lea County, NM and one
in Howard County, TX. Based on current strip pricing, we anticipate
spending our $37 million capital budget but may deviate from such
plans based on market conditions.
2016 Asset Sales Update
Through Q2 2016, we closed 18 divestitures
generating net proceeds of $87.5 million. Below are the summary
statistics of year to date sales:
Transaction Statistics:
Total Sales Price |
$ |
87,469,448 |
|
Transaction Count |
18 |
|
County Count |
38 |
|
Total Net Acreage |
54,660 |
|
Midland Basin Net Acreage (1) |
9,679 |
|
Approximated % of Year-End 2015
Midland Basin Acreage (1) |
51 |
% |
Average Gross Midland Basin Tract
Size (acres) |
181 |
|
Q4 2015 Production (Boe/d) |
953 |
|
Cash Flow (2) |
$ |
(536,869 |
) |
Total Gross Well Count (3) |
733 |
|
YE 2015 PUDs |
2 |
|
$ / Net Midland Basin Acre (4) |
$ |
7,874 |
|
______________________
(1) Excludes our and TSSP's combined interests in
approximately 4,092 net acres in the Midland Basin committed to the
parties' development agreement.
(2) Estimate based on last twelve months prior to
closing each transaction.
(3) Includes producing, injecting, shut-in and PUD
wells.
(4) Calculated as sales price received attributable
to Midland Basin acreage divided by Midland Basin acreage.
In July and early August, we completed three
additional divestments of properties outside the Midland Basin for
approximately $5.0 million, bringing our year-to-date total to
$92.5 million.
Capital Structure Update
Through August 1, 2016, we have reduced our
year-end 2015 total debt outstanding by $272.4 million. Our debt
balances as of each of the respective dates are as follows:
|
12/31/2015 |
6/30/2016 |
8/1/2016 |
|
(In thousands) |
Credit Facility due
2019 |
$ |
608,000 |
|
$ |
533,000 |
|
$ |
520,000 |
|
8% Senior Notes
(1) |
300,000 |
|
232,989 |
|
232,989 |
|
6.625% Senior Notes
(1) |
550,000 |
|
432,656 |
|
432,656 |
|
Total Debt Outstanding
(1) |
$ |
1,458,000 |
|
$ |
1,198,645 |
|
$ |
1,185,645 |
|
________________________________________________
(1) Excludes unamortized discount on Senior
Notes.
Given our borrowing base of $630 million,
outstanding borrowings of $520 million and $1.4 million of
outstanding letters of credit, we currently have $108.6 million of
availability.
Near-Term Outlook and
Commentary
Paul T. Horne, Chairman, President and Chief
Executive Officer of Legacy's general partner commented, “I am
proud of the progress we made in Q2 and over the past several
quarters. The difficult macro environment remains challenging but
our team continues to make meaningful operational improvements. LOE
was down 11% from last quarter and down 3% relative to Q2 2015,
which is very impressive, given the significant increase in our
property base from our acquisition of East Texas properties. We
remain incredibly disciplined with our capital spending. Under our
horizontal development program with TSSP, we have funded $4.1
million of capital to date and averaged approximately 850 Boe/d of
net production in the quarter. With great asset-level results in
that program, we recently resumed drilling under the first tranche
with a rig running in both Lea County, NM and Howard County,
TX.
Consistent with our view last quarter, we continue
to focus on maintaining liquidity and reducing debt outstanding and
therefore we have no near-term plans to resume our distributions on
either our preferred units or common units. As always, we will
continue to closely watch the market and respond with business
objectives that match accordingly.”
Dan Westcott, Executive Vice President and Chief
Financial Officer of Legacy's general partner commented, “We again
improved our balance sheet this quarter. Year-to-date, our
internally generated free cash flow and $92 million of asset sales
has enhanced our liquidity, reduced future plugging obligations,
and improved our leverage statistics. We've reduced total debt by
$272.4 million and currently have over $100 million of availability
under our $630 million borrowing base. Given the volatility of the
macro environment, we continue to review alternatives for the
business including, among others, additional asset
sales and new sources of capital. As noted in the
included tables, we've recently added commodity hedges to mitigate
some of the impact of the market volatility. In the past few
months, we increased our 2H 2016 oil hedges from 29% to 63% of
current production and increased 2017 from 10% to 46%. We also
increased our 2H 2016 gas hedges from 52% to 82% of current
production and increased 2017 from 49% to 54%. We continue to
monitor further hedge opportunities, and would have hedged
additional volumes, but unfortunately, our banks have been
unwilling to act as counterparty for additional hedges, which we
believe is based on our credit profile and their desire to reduce
exposure to the oil and gas sector. Commodity prices have improved
since our last quarterly report and our internally projected cash
flow has correspondingly increased, but we remain largely exposed
to commodity price volatility. Our plans remain flexible to the
environment in which we operate, and as Paul mentioned, we will
adjust accordingly to position Legacy for success.”
LEGACY RESERVES LP |
SELECTED FINANCIAL AND OPERATING
DATA |
|
|
Three Months Ended |
|
Six Months Ended |
|
June 30, |
|
June 30, |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
|
(In thousands, except per unit
data) |
Revenues: |
|
|
|
|
|
|
|
Oil sales |
$ |
41,272 |
|
|
$ |
59,113 |
|
|
$ |
71,592 |
|
|
$ |
109,409 |
|
Natural gas liquids sales |
3,922 |
|
|
5,729 |
|
|
6,375 |
|
|
9,921 |
|
Natural gas sales |
28,173 |
|
|
22,959 |
|
|
61,259 |
|
|
50,010 |
|
Total revenue |
$ |
73,367 |
|
|
$ |
87,801 |
|
|
$ |
139,226 |
|
|
$ |
169,340 |
|
Expenses: |
|
|
|
|
|
|
|
Oil and natural gas production,
excluding ad valorem taxes |
$ |
41,520 |
|
|
$ |
42,828 |
|
|
$ |
88,181 |
|
|
$ |
88,772 |
|
Ad valorem taxes |
$ |
3,041 |
|
|
$ |
2,392 |
|
|
$ |
6,403 |
|
|
$ |
5,668 |
|
Total oil and natural gas
production |
$ |
44,561 |
|
|
$ |
45,220 |
|
|
$ |
94,584 |
|
|
$ |
94,440 |
|
Production and other taxes |
$ |
3,390 |
|
|
$ |
3,986 |
|
|
$ |
5,963 |
|
|
$ |
8,204 |
|
General and administrative,
excluding trans. related costs and LTIP |
$ |
7,777 |
|
|
$ |
6,549 |
|
|
$ |
15,469 |
|
|
$ |
14,305 |
|
Transaction related costs |
$ |
714 |
|
|
$ |
1,648 |
|
|
$ |
791 |
|
|
$ |
1,673 |
|
LTIP expense |
$ |
2,502 |
|
|
$ |
2,193 |
|
|
$ |
4,167 |
|
|
$ |
3,281 |
|
Total general and
administrative |
$ |
10,993 |
|
|
$ |
10,390 |
|
|
$ |
20,427 |
|
|
$ |
19,259 |
|
Depletion, depreciation,
amortization and accretion |
$ |
37,668 |
|
|
$ |
36,197 |
|
|
$ |
74,627 |
|
|
$ |
77,265 |
|
Commodity derivative
cash settlements: |
|
|
|
|
|
|
|
Oil derivative cash settlements
received |
$ |
9,760 |
|
|
$ |
27,364 |
|
|
$ |
22,345 |
|
|
$ |
59,564 |
|
Natural gas derivative cash
settlements received |
$ |
12,333 |
|
|
$ |
9,825 |
|
|
$ |
22,525 |
|
|
$ |
17,962 |
|
Production: |
|
|
|
|
|
|
|
Oil (MBbls) |
1,039 |
|
|
1,171 |
|
|
2,108 |
|
|
2,371 |
|
Natural gas liquids (MGal) |
9,663 |
|
|
11,566 |
|
|
17,904 |
|
|
21,252 |
|
Natural gas (MMcf) |
16,743 |
|
|
9,649 |
|
|
34,009 |
|
|
19,307 |
|
Total (MBoe) |
4,060 |
|
|
3,055 |
|
|
8,202 |
|
|
6,095 |
|
Average daily production
(Boe/d) |
44,615 |
|
|
33,571 |
|
|
45,066 |
|
|
33,674 |
|
Average sales price per
unit (excluding derivative cash settlements): |
|
|
|
|
|
|
|
Oil price (per Bbl) |
$ |
39.72 |
|
|
$ |
50.48 |
|
|
$ |
33.96 |
|
|
$ |
46.14 |
|
Natural gas liquids price (per
Gal) |
$ |
0.41 |
|
|
$ |
0.50 |
|
|
$ |
0.36 |
|
|
$ |
0.47 |
|
Natural gas price (per Mcf) |
$ |
1.68 |
|
|
$ |
2.38 |
|
|
$ |
1.80 |
|
|
$ |
2.59 |
|
Combined (per Boe) |
$ |
18.07 |
|
|
$ |
28.74 |
|
|
$ |
16.97 |
|
|
$ |
27.78 |
|
Average sales price per
unit (including derivative cash settlements): |
|
|
|
|
|
|
|
Oil price (per Bbl) |
$ |
49.12 |
|
|
$ |
73.85 |
|
|
$ |
44.56 |
|
|
$ |
71.27 |
|
Natural gas liquids price (per
Gal) |
$ |
0.41 |
|
|
$ |
0.50 |
|
|
$ |
0.36 |
|
|
$ |
0.47 |
|
Natural gas price (per Mcf) |
$ |
2.42 |
|
|
$ |
3.40 |
|
|
$ |
2.46 |
|
|
$ |
3.52 |
|
Combined (per Boe) |
$ |
23.51 |
|
|
$ |
40.91 |
|
|
$ |
22.45 |
|
|
$ |
40.50 |
|
Average WTI oil spot
price (per Bbl) |
$ |
45.46 |
|
|
$ |
57.85 |
|
|
$ |
39.55 |
|
|
$ |
53.25 |
|
Average Henry Hub
natural gas index price (per Mcf) |
$ |
2.15 |
|
|
$ |
2.77 |
|
|
$ |
2.07 |
|
|
$ |
2.82 |
|
Average unit costs per
Boe: |
|
|
|
|
|
|
|
Oil and natural gas production,
excluding ad valorem taxes |
$ |
10.23 |
|
|
$ |
14.02 |
|
|
$ |
10.75 |
|
|
$ |
14.56 |
|
Ad valorem taxes |
$ |
0.75 |
|
|
$ |
0.78 |
|
|
$ |
0.78 |
|
|
$ |
0.93 |
|
Production and other taxes |
$ |
0.83 |
|
|
$ |
1.30 |
|
|
$ |
0.73 |
|
|
$ |
1.35 |
|
General and administrative
excluding trans. related costs and LTIP |
$ |
1.92 |
|
|
$ |
2.14 |
|
|
$ |
1.89 |
|
|
$ |
2.35 |
|
Total general and
administrative |
$ |
2.71 |
|
|
$ |
3.40 |
|
|
$ |
2.49 |
|
|
$ |
3.16 |
|
Depletion, depreciation,
amortization and accretion |
$ |
9.28 |
|
|
$ |
11.85 |
|
|
$ |
9.10 |
|
|
$ |
12.68 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial and Operating Results -
Three-Month Period Ended June 30, 2016 Compared to Three-Month
Period Ended June 30, 2015
- Production increased 33% to 44,615 Boe/d from 33,571 Boe/d
primarily due to our acquisitions in the second half of 2015
including our acquisitions of East Texas properties.
- Average realized price, excluding net cash settlements from
commodity derivatives, decreased 37% to $18.07 per Boe in 2016 from
$28.74 per Boe in 2015 driven by the significant decline in
commodity prices as well as the increase of natural gas production
as a percentage of total production. Average realized oil price
decreased 21% to $39.72 in 2016 from $50.48 in 2015 driven by a
decrease in the average West Texas Intermediate ("WTI") crude oil
price of $12.39 per Bbl partially offset by an improvement in
realized regional differentials. Average realized natural gas price
decreased 29% to $1.68 per Mcf in 2016 from $2.38 per Mcf in 2015.
This decrease is primarily a result of the decrease in the average
Henry Hub natural gas index price of $0.62 per Mcf. Finally, our
average realized NGL price decreased 18% to $0.41 per gallon in
2016 from $0.50 per gallon in 2015.
- Production expenses, excluding ad valorem taxes, decreased 3%
to $41.5 million in 2016 from $42.8 million in 2015, primarily due
to cost reduction efforts on historical properties, partially
offset by production expenses related to our acquisition of East
Texas properties ($7.5 million). On an average cost per Boe basis,
production expenses excluding ad valorem taxes decreased 27% to
$10.23 per Boe in 2016 from $14.02 per Boe in 2015, driven
primarily by the inclusion of lower cost production from our
acquired East Texas properties as well as cost reduction efforts in
our historical properties.
- General and administrative expenses, excluding unit-based
Long-Term Incentive Plan compensation expense increased to $8.5
million in 2016 from $8.2 million in 2015, reflecting cost
reduction efforts partially offsetting increases in salaries and
wages commensurate with a larger asset base following our
acquisition of East Texas properties.
- Cash settlements received on our commodity derivatives during
2016 were $22.1 million compared to $37.2 million in 2015. While
commodity prices were lower in 2016, the decline in cash
settlements received is a result of the reduced nominal volumes
hedges in Q2 2016 compared to Q2 2015.
- Total development capital expenditures decreased to $6.9
million in 2016 from $8.4 million in 2015. The 2016 activity was
comprised mainly of the drilling and completion of joint
development agreement wells and capital costs related to CO2
properties.
Financial and Operating Results - Six-Month
Period Ended June 30, 2016 Compared to Six-Month Period Ended
June 30, 2015
- Production increased 34% to 45,066 Boe/d from 33,674 Boe/d
primarily due to acquisitions in the second half of 2015 including
the acquisition of East Texas properties.
- Average realized price, excluding net cash settlements from
commodity derivatives, decreased 39% to $16.97 per Boe in 2016 from
$27.78 per Boe in 2015 driven by the significant decline in
commodity prices as well as the increase in NGL and natural gas
production as a percentage of total production. Average realized
oil price decreased 26% to $33.96 in 2016 from $46.14 in 2015
driven by a decrease in the average WTI crude oil price of $13.70
per Bbl partially offset by an improvement in realized regional
differentials. Average realized natural gas price decreased 31% to
$1.80 per Mcf in 2016 from $2.59 per Mcf in 2015. This decrease is
a result of the decrease in the average Henry Hub natural gas index
price of approximately $0.75 per Mcf. Finally, our average realized
NGL price decreased 23% to $0.36 per gallon in 2016 from $0.47 per
gallon in 2015. This decrease is due to lower commodity
prices.
- Despite additional expenses from our acquisition of East Texas
properties of approximately $16.2 million, our production expenses,
excluding ad valorem taxes, decreased 1% to $88.2 million in 2016
from $88.8 million in 2015. On an average cost per Boe basis,
production expenses decreased 26% to $10.75 per Boe in 2016 from
$14.56 per Boe in 2015. These significant savings were driven
primarily by expense reduction efforts across our historical
property set ($16.8 million) as well as the inclusion of lower cost
natural gas properties acquired in East Texas.
- Non-cash impairment expense totaled $15.4 million driven by the
continued decline in commodities futures prices during the first
quarter of 2016.
- General and administrative expenses, excluding unit-based LTIP
compensation expense totaled $16.3 million in 2016 compared to
$16.0 million in 2015, reflecting cost reduction efforts partially
offsetting increases in salaries and wages commensurate with a
larger asset base following our acquisition of East Texas
properties.
- Cash settlements received on our commodity derivatives during
2016 were $44.9 million compared to receipts of $77.5 million in
2015. While commodity prices were lower in 2016, the decline in
cash settlements received is a result of the reduced nominal
volumes hedges in Q2 2016 compared to Q2 2015.
- Total development capital expenditures decreased to $11.7
million in 2016 from $21.8 million in 2015. The 2016 activity was
comprised mainly of the drilling and completion of joint
development agreement wells and capital costs related to CO2
properties.
Commodity Derivative ContractsWe
enter into oil and natural gas derivative contracts to help
mitigate the risk of changing commodity prices. As of
August 1, 2016, we had entered into derivative agreements to
receive average NYMEX WTI crude oil prices and NYMEX Henry Hub,
Waha, NWPL, SoCal and San Juan natural gas prices as summarized
below.
WTI Crude Oil Swaps:
Time Period |
|
Volumes (Bbls) |
|
Average Price per Bbl |
|
Price Range per Bbl |
July-December 2016 |
|
1,002,800 |
|
|
$ |
55.24 |
|
|
$ |
50.15 |
|
- |
$ |
91.00 |
|
2017 |
|
182,500 |
|
|
$ |
84.75 |
|
|
$ |
84.75 |
|
WTI Crude Oil Costless Collars. At an average WTI
market price of $40.00, $50.00 and $60.00, the summary position
below would result in a net price of $45.00, $50.00 and $58.89,
respectively.
|
|
|
|
Average Short |
|
Average Long |
Time Period |
|
Volumes (Bbls) |
|
Put Price per Bbl |
|
Put Price per Bbl |
2017 |
|
1,460,000 |
|
$ |
45.00 |
|
|
$ |
58.89 |
|
WTI Crude Oil 3-Way Collars. At an average WTI
market price of $40.00, the summary positions below would result in
a net price of $65.00 for the remainder of 2016 and 2017:
|
|
|
|
Average Short Put |
|
Average Long Put |
|
Average Short Call |
Time Period |
|
Volumes (Bbls) |
|
Price per Bbl |
|
Price per Bbl |
|
Price per Bbl |
July-December 2016 |
|
230,000 |
|
|
$ |
60.00 |
|
|
$ |
85.00 |
|
|
$ |
102.46 |
|
2017 |
|
72,400 |
|
|
$ |
60.00 |
|
|
$ |
85.00 |
|
|
$ |
104.20 |
|
WTI Crude Oil Enhanced Swaps. At an average WTI
market price of $40.00, the summary positions below would result in
a net price of $66.70, $65.85 and $65.50 for the remainder of 2016,
2017 and 2018, respectively:
|
|
|
|
Average Long Put |
|
Average Short Put |
|
Average Swap |
Time Period |
|
Volumes (Bbls) |
|
Price per Bbl |
|
Price per Bbl |
|
Price per Bbl |
July-December 2016 |
|
92,000 |
|
|
$ |
57.00 |
|
|
$ |
82.00 |
|
|
$ |
91.70 |
|
2017 |
|
182,500 |
|
|
$ |
57.00 |
|
|
$ |
82.00 |
|
|
$ |
90.85 |
|
2018 |
|
127,750 |
|
|
$ |
57.00 |
|
|
$ |
82.00 |
|
|
$ |
90.50 |
|
Midland-to-Cushing WTI Crude Oil Differential
Swaps:
Time Period |
|
Volumes (Bbls) |
|
Average Price per Bbl |
|
Price Range per Bbl |
July-December 2016 |
|
1,472,000 |
|
|
$ |
(1.60 |
) |
|
$ |
(1.50 |
) |
- |
$ |
(1.75 |
) |
2017 |
|
2,190,000 |
|
|
$ |
(0.30 |
) |
|
$ |
(0.05 |
) |
- |
$ |
(0.75 |
) |
Natural Gas Swaps (Henry Hub and Waha):
|
|
|
|
Average |
|
|
|
|
Time Period |
|
Volumes (MMBtu) |
|
Price per MMBtu |
|
Price Range per MMBtu |
July-December 2016 |
|
24,973,600 |
|
|
$ |
3.01 |
|
|
$ |
2.42 |
|
- |
$ |
5.30 |
|
2017 |
|
27,600,000 |
|
|
$ |
3.36 |
|
|
$ |
3.29 |
|
- |
$ |
3.39 |
|
2018 |
|
27,600,000 |
|
|
$ |
3.36 |
|
|
$ |
3.29 |
|
- |
$ |
3.39 |
|
2019 |
|
25,800,000 |
|
|
$ |
3.36 |
|
|
$ |
3.29 |
|
- |
$ |
3.39 |
|
Natural Gas Costless Collars (Henry Hub). At an
average Henry Hub market price of $2.50, $3.00 and $3.50, the
summary position below would result in a net price of $2.90, $3.00
and $3.44, respectively.
|
|
|
|
Average Short |
|
Average Long |
Time Period |
|
Volumes (Bbls) |
|
Put Price per Bbl |
|
Put Price per Bbl |
2017 |
|
14,600,000 |
|
$ |
2.90 |
|
|
$ |
3.44 |
|
Natural Gas 3-Way Collars (Henry Hub). At an annual
average Henry Hub market price of $2.50, the summary positions
below would result in a net price of $3.00 for the remainder of
2016 and 2017:
|
|
Volumes |
|
Average Short Put |
|
Average Long Put |
|
Average Short Call |
Time Period |
|
(MMBtu) |
|
Price per MMBtu |
|
Price per MMBtu |
|
Price per MMBtu |
July-December 2016 |
|
2,790,000 |
|
$ |
3.75 |
|
|
$ |
4.25 |
|
|
$ |
5.08 |
|
2017 |
|
5,040,000 |
|
$ |
3.75 |
|
|
$ |
4.25 |
|
|
$ |
5.53 |
|
Natural Gas Basis Swaps (NWPL, SoCal and San
Juan)
|
|
July-December 2016 |
|
2017 |
|
|
|
|
Average |
|
|
|
Average |
|
|
Volumes (MMBtu) |
|
Price per MMBtu |
|
Volumes (MMBtu) |
|
Price per MMBtu |
NWPL |
|
7,529,832 |
|
$ |
(0.19 |
) |
|
7,300,000 |
|
$ |
(0.16 |
) |
SoCal |
|
— |
|
$ |
— |
|
|
2,500,250 |
|
$ |
0.11 |
|
San Juan |
|
1,256,720 |
|
$ |
(0.16 |
) |
|
2,500,250 |
|
$ |
(0.10 |
) |
Location and quality differentials attributable to
our properties are not reflected in the above prices. The
agreements provide for monthly settlement based on the difference
between the agreement fixed price and the actual reference oil and
natural gas index prices.
Quarterly Report on Form 10-Q
Financial results contained herein are preliminary
and subject to the final, unaudited financial statements and
related footnotes included in Legacy's Form 10-Q which will be
filed on or about August 3, 2016.
Conference Call
As announced on July 12, 2016, Legacy will host an
investor conference call to discuss Legacy's results on Thursday,
August 4, 2016 at 9:00 a.m. (Central Time). Those wishing to
participate in the conference call should dial 877-266-0479. A
replay of the call will be available through Thursday, August 11,
2016, by dialing 855-859-2056 or 404-537-3406 and entering replay
code 49069846. Those wishing to listen to the live or archived web
cast via the Internet should go to the Investor Relations tab of
our website at www.LegacyLP.com. Following our prepared remarks, we
will be pleased to answer questions from securities analysts and
institutional portfolio managers and analysts; the complete call is
open to all other interested parties on a listen-only basis.
Additional Information for Holders of
Legacy Units
Although Legacy has suspended distributions to both
the 8% Series A and Series B Fixed-to-Floating Rate Cumulative
Redeemable Perpetual Preferred Units (the "Preferred Units"), such
distributions continue to accrue. Pursuant to the terms of Legacy's
partnership agreement, Legacy is required to pay or set aside for
payment all accrued but unpaid distributions with respect to the
Preferred Units prior to or contemporaneously with making any
distribution with respect to Legacy's units. Accruals of
distributions on the Preferred Units are treated for tax purposes
as guaranteed payments for the use of capital that will generally
be taxable to the holders of such Preferred Units as ordinary
income even in the absence of contemporaneous distributions.
In addition, Legacy’s unitholders, just like
unitholders of other master limited partnerships, are allocated
taxable income irrespective of cash distributions paid. Because
Legacy’s unitholders are treated as partners that are allocated a
share of Legacy’s taxable income irrespective of the amount of
cash, if any, distributed by Legacy, unitholders will be required
to pay federal income taxes and, in some cases, state and local
income taxes on their share of Legacy’s taxable income, including
its taxable income associated with cancellation of debt ("COD
income") or a disposition of property by Legacy, even if they
receive no cash distributions from Legacy. As of January 21, 2016,
Legacy has suspended all cash distributions to unitholders and
holders of the Preferred Units. Legacy may engage in transactions
to de-lever the Partnership and manage its liquidity that may
result in the allocation of income and gain to its unitholders
without a corresponding cash distribution. For example, during the
six month period ended June 30, 2016, Legacy closed 18 divestitures
generating net proceeds of $87.5 million, and Legacy may sell
additional assets and use the proceeds to repay existing debt or
fund capital expenditure, in which case Legacy’s unitholders may be
allocated taxable income and gain resulting from the sale, all or a
portion of which may be subject to recapture rules and taxed as
ordinary income rather than capital gain, without receiving a cash
distribution. Further, Legacy may pursue other opportunities to
reduce its existing debt, such as debt exchanges, debt repurchases,
or modifications that would result in COD income being allocated to
its unitholders as ordinary taxable income. The ultimate effect of
any income allocations will depend on the unitholder's individual
tax position with respect to its units, including the availability
of any current or suspended passive losses that may offset some
portion of the COD income allocable to a unitholder. Unitholders
are encouraged to consult their tax advisors with respect to the
consequences of potential transactions that may result in income
and gain to unitholders.
Additionally, if Legacy’s unitholders, just like
unitholders of other master limited partnerships, sell any of their
units, they will recognize gain or loss equal to the difference
between the amount realized and their tax basis in those units.
Prior distributions to unitholders that in the aggregate
exceeded the cumulative net taxable income they were allocated for
a unit decreased the tax basis in that unit, and will, in effect,
become taxable income to Legacy’s unitholders if the unit is sold
at a price greater than their tax basis in that unit, even if the
price received is less than original cost. A substantial portion of
the amount realized, whether or not representing gain, may be
ordinary income to Legacy’s unitholders due to the potential
recapture items, including depreciation, depletion and intangible
drilling.
About Legacy Reserves LP
Legacy Reserves LP is a master limited partnership
headquartered in Midland, Texas, focused on the acquisition and
development of oil and natural gas properties primarily located in
the Permian Basin, East Texas, Rocky Mountain and Mid-Continent
regions of the United States. Additional information is available
at www.LegacyLP.com.
Cautionary Statement Relevant to
Forward-Looking Information
This press release contains forward-looking
statements relating to our operations that are based on
management's current expectations, estimates and projections about
its operations. Words such as "anticipates," "expects," "intends,"
"plans," "targets," "projects," "believes," "seeks," "schedules,"
"estimated," and similar expressions are intended to identify such
forward-looking statements. These statements are not guarantees of
future performance and are subject to certain risks, uncertainties
and other factors, some of which are beyond our control and are
difficult to predict. Among the important factors that could cause
actual results to differ materially from those in the
forward-looking statements are: realized oil and natural gas
prices; production volumes, lease operating expenses, general and
administrative costs and finding and development costs; future
operating results and the factors set forth under the heading "Risk
Factors" in our annual and quarterly reports filed with the SEC.
Therefore, actual outcomes and results may differ materially from
what is expressed or forecasted in such forward-looking statements.
The reader should not place undue reliance on these forward-looking
statements, which speak only as of the date of this press release.
Unless legally required, Legacy undertakes no obligation to update
publicly any forward-looking statements, whether as a result of new
information, future events or otherwise.
LEGACY RESERVES LP |
CONDENSED CONSOLIDATED STATEMENTS OF
OPERATIONS |
(UNAUDITED) |
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
|
|
2016 |
|
2015 |
|
2016 |
|
2015 |
|
|
(In thousands, except per unit
data) |
Revenues: |
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
41,272 |
|
|
$ |
59,113 |
|
|
$ |
71,592 |
|
|
$ |
109,409 |
|
Natural gas liquids (NGL)
sales |
|
3,922 |
|
|
5,729 |
|
|
6,375 |
|
|
9,921 |
|
Natural gas sales |
|
28,173 |
|
|
22,959 |
|
|
61,259 |
|
|
50,010 |
|
Total revenues |
|
73,367 |
|
|
87,801 |
|
|
139,226 |
|
|
169,340 |
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
Oil and natural gas production |
|
44,561 |
|
|
45,220 |
|
|
94,584 |
|
|
94,440 |
|
Production and other taxes |
|
3,390 |
|
|
3,986 |
|
|
5,963 |
|
|
8,204 |
|
General and administrative |
|
10,993 |
|
|
10,390 |
|
|
20,427 |
|
|
19,259 |
|
Depletion, depreciation,
amortization and accretion |
|
37,668 |
|
|
36,197 |
|
|
74,627 |
|
|
77,265 |
|
Impairment of long-lived
assets |
|
— |
|
|
— |
|
|
15,447 |
|
|
209,402 |
|
(Gain) loss on disposal of
assets |
|
(9,141 |
) |
|
(934 |
) |
|
(40,842 |
) |
|
1,007 |
|
Total expenses |
|
87,471 |
|
|
94,859 |
|
|
170,206 |
|
|
409,577 |
|
|
|
|
|
|
|
|
|
|
Operating loss |
|
(14,104 |
) |
|
(7,058 |
) |
|
(30,980 |
) |
|
(240,237 |
) |
|
|
|
|
|
|
|
|
|
Other income
(expense): |
|
|
|
|
|
|
|
|
Interest income |
|
16 |
|
|
176 |
|
|
54 |
|
|
382 |
|
Interest expense |
|
(20,302 |
) |
|
(17,760 |
) |
|
(45,478 |
) |
|
(35,552 |
) |
Gain on extinguishment of debt |
|
19,998 |
|
|
— |
|
|
150,802 |
|
|
— |
|
Equity in income (loss) of equity
method investees |
|
(9 |
) |
|
24 |
|
|
(14 |
) |
|
103 |
|
Net gains (losses) on commodity
derivatives |
|
(37,675 |
) |
|
(13,497 |
) |
|
(20,637 |
) |
|
6,983 |
|
Other |
|
(98 |
) |
|
97 |
|
|
(192 |
) |
|
702 |
|
Incomes (loss) before income
taxes |
|
(52,174 |
) |
|
(38,018 |
) |
|
53,555 |
|
|
(267,619 |
) |
Income tax (expense)
benefit |
|
(87 |
) |
|
(456 |
) |
|
(487 |
) |
|
291 |
|
Net income (loss) |
|
$ |
(52,261 |
) |
|
$ |
(38,474 |
) |
|
$ |
53,068 |
|
|
$ |
(267,328 |
) |
Distributions to Preferred
unitholders |
|
(4,750 |
) |
|
(4,750 |
) |
|
(8,708 |
) |
|
(9,500 |
) |
Net income (loss) attributable to
unitholders |
|
$ |
(57,011 |
) |
|
$ |
(43,224 |
) |
|
$ |
44,360 |
|
|
$ |
(276,828 |
) |
|
|
|
|
|
|
|
|
|
Income (loss) per unit - basic and
diluted |
|
$ |
(0.81 |
) |
|
$ |
(0.63 |
) |
|
$ |
0.64 |
|
|
$ |
(4.02 |
) |
Weighted average number of units
used in computing net income (loss) per unit - |
|
|
|
|
|
|
|
|
Basic and diluted |
|
70,071 |
|
|
68,897 |
|
|
69,518 |
|
|
68,909 |
|
|
LEGACY RESERVES LP |
CONDENSED CONSOLIDATED BALANCE
SHEETS |
(UNAUDITED) |
|
ASSETS |
|
|
June 30, 2016 |
|
December 31, 2015 |
|
|
(In thousands) |
Current assets: |
|
|
|
|
Cash and cash equivalents |
|
$ |
1,140 |
|
|
$ |
2,006 |
|
Accounts receivable, net: |
|
|
|
|
Oil and natural gas |
|
35,578 |
|
|
33,944 |
|
Joint interest owners |
|
13,752 |
|
|
25,378 |
|
Other |
|
2 |
|
|
86 |
|
Fair value of derivatives |
|
23,188 |
|
|
63,711 |
|
Prepaid expenses and other current
assets |
|
7,724 |
|
|
4,334 |
|
Total current assets |
|
81,384 |
|
|
129,459 |
|
Oil and natural gas
properties using the successful efforts method, at cost: |
|
|
|
|
Proved properties |
|
3,307,925 |
|
|
3,485,634 |
|
Unproved properties |
|
13,653 |
|
|
13,424 |
|
Accumulated depletion,
depreciation, amortization and impairment |
|
(2,048,928 |
) |
|
(2,090,102 |
) |
|
|
1,272,650 |
|
|
1,408,956 |
|
Other property and
equipment, net of accumulated depreciation and amortization of
$9,754 and $8,915, respectively |
|
4,048 |
|
|
4,575 |
|
Operating rights, net
of amortization of $5,161 and $4,953, respectively |
|
1,856 |
|
|
2,064 |
|
Fair value of
derivatives |
|
30,254 |
|
|
56,373 |
|
Other assets |
|
10,109 |
|
|
11,047 |
|
Investments in equity
method investees |
|
633 |
|
|
646 |
|
Total assets |
|
$ |
1,400,934 |
|
|
$ |
1,613,120 |
|
LIABILITIES AND PARTNERS' DEFICIT |
Current
liabilities: |
|
|
|
|
Accounts payable |
|
$ |
3,722 |
|
|
$ |
13,581 |
|
Accrued oil and natural gas
liabilities |
|
55,086 |
|
|
50,573 |
|
Fair value of derivatives |
|
3,047 |
|
|
2,019 |
|
Asset retirement obligation |
|
3,496 |
|
|
3,496 |
|
Other |
|
7,594 |
|
|
11,424 |
|
Total current liabilities |
|
72,945 |
|
|
81,093 |
|
Long-term debt |
|
1,173,009 |
|
|
1,427,614 |
|
Asset retirement
obligation |
|
266,427 |
|
|
282,909 |
|
Fair value of
derivatives |
|
3,469 |
|
|
— |
|
Other long-term
liabilities |
|
1,195 |
|
|
1,181 |
|
Total liabilities |
|
1,517,045 |
|
|
1,792,797 |
|
Commitments and
contingencies |
|
|
|
|
Partners' equity |
|
|
|
|
Series A Preferred equity -
2,300,000 units issued and outstanding at June 30, 2016 and
December 31, 2015 |
|
55,192 |
|
|
55,192 |
|
Series B Preferred equity -
7,200,000 units issued and outstanding at June 30, 2016 and
December 31, 2015 |
|
174,261 |
|
|
174,261 |
|
Incentive distribution equity -
100,000 units issued and outstanding at June 30, 2016 and December
31, 2015 |
|
30,814 |
|
|
30,814 |
|
Limited partners' deficit -
72,055,697 and 68,949,961 units issued and outstanding at June 30,
2016 and December 31, 2015, respectively |
|
(376,260 |
) |
|
(439,811 |
) |
General partner's deficit
(approximately 0.03%) |
|
(118 |
) |
|
(133 |
) |
Total partners' deficit |
|
(116,111 |
) |
|
(179,677 |
) |
Total liabilities and
partners' deficit |
|
$ |
1,400,934 |
|
|
$ |
1,613,120 |
|
|
|
|
|
|
|
|
|
|
Non-GAAP Financial Measures
This press release, the financial tables and other
supplemental information include "Adjusted EBITDA" and
"Distributable Cash Flow", both of which are non-generally accepted
accounting principles ("non-GAAP") measures which may be used
periodically by management when discussing our financial results
with investors and analysts. The following presents a
reconciliation of each of these non-GAAP financial measures to
their nearest comparable generally accepted accounting principles
("GAAP") measure.
Adjusted EBITDA and Distributable Cash Flow are
presented as management believes they provide additional
information concerning the performance of our business and are used
by investors and financial analysts to analyze and compare our
current operating and financial performance relative to past
performance and such performances relative to that of other
publicly traded partnerships in the industry. Adjusted EBITDA and
Distributable Cash Flow may not be comparable to similarly titled
measures of other publicly traded limited partnerships or limited
liability companies because all companies may not calculate such
measures in the same manner.
Distributable Cash Flow is one of the factors used
by the board of directors of our general partner (the “Board”) to
help determine the amount of Available Cash as defined in our
partnership agreement, that is to be distributed to our unitholders
for such period. Under our partnership agreement, Available Cash is
defined generally to mean, cash on hand at the end of each quarter,
plus working capital borrowings made after the end of the quarter,
less cash reserves determined by our general partner. The Board
determines whether to increase, maintain or decrease the current
level of distributions in accordance with the provisions of our
partnership agreement based on a variety of factors, including
without limitation, Distributable Cash Flow, cash reserves
established in prior periods, reserves established for future
periods, borrowing capacity for working capital, temporary,
one-time or uncharacteristic historical results, and forecasts of
future period results including the impact of pending acquisitions.
Management and the Board consider the long-term view of expected
results in determining the amount of its distributions. Certain
factors impacting Adjusted EBITDA and Distributable Cash Flow may
be viewed as temporary, one-time in nature, or being offset by
reserves from past performance or near-term future performance.
Financial results are also driven by various factors that do not
typically occur evenly throughout the year that are difficult to
predict, including rig availability, weather, well performance, the
timing of drilling and completions and near-term commodity price
changes. Consistent with practices common to publicly traded
partnerships, the Board historically has not varied the
distribution it declares based on such timing effects.
"Adjusted EBITDA" and "Distributable Cash Flow"
should not be considered as alternatives to GAAP measures, such as
net income, operating income, cash flow from operating activities,
or any other GAAP measure of financial performance.
The following table presents a reconciliation of
our consolidated net income (loss) to Adjusted EBITDA and
Distributable Cash Flow:
|
Three Months Ended |
|
Six Months Ended |
|
June 30, |
|
June 30, |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
|
(In thousands) |
Net income
(loss) |
$ |
(52,261 |
) |
|
$ |
(38,474 |
) |
|
$ |
53,068 |
|
|
$ |
(267,328 |
) |
Plus: |
|
|
|
|
|
|
|
Interest expense |
20,302 |
|
|
17,760 |
|
|
45,478 |
|
|
35,552 |
|
Gain on extinguishment of debt |
(19,998 |
) |
|
— |
|
|
(150,802 |
) |
|
— |
|
Income tax expense (benefit) |
87 |
|
|
456 |
|
|
487 |
|
|
(291 |
) |
Depletion, depreciation,
amortization and accretion |
37,668 |
|
|
36,197 |
|
|
74,627 |
|
|
77,265 |
|
Impairment of long-lived
assets |
— |
|
|
— |
|
|
15,447 |
|
|
209,402 |
|
(Gain) loss on disposal of
assets |
(9,141 |
) |
|
(934 |
) |
|
(40,842 |
) |
|
1,007 |
|
Equity in (income) loss of equity
method investees |
9 |
|
|
(24 |
) |
|
14 |
|
|
(103 |
) |
Unit-based compensation
expense |
2,502 |
|
|
2,193 |
|
|
4,167 |
|
|
3,281 |
|
Minimum payments received in excess
of overriding royalty interest earned(1) |
— |
|
|
377 |
|
|
802 |
|
|
744 |
|
Equity in EBITDA of equity method
investee(2) |
— |
|
|
50 |
|
|
— |
|
|
169 |
|
Net (gains) losses on commodity
derivatives |
37,675 |
|
|
13,497 |
|
|
20,637 |
|
|
(6,983 |
) |
Net cash settlements received on
commodity derivatives |
22,093 |
|
|
37,189 |
|
|
44,870 |
|
|
77,526 |
|
Transaction related expenses |
714 |
|
|
1,648 |
|
|
791 |
|
|
1,673 |
|
Adjusted
EBITDA |
$ |
39,650 |
|
|
$ |
69,935 |
|
|
$ |
68,744 |
|
|
$ |
131,914 |
|
|
|
|
|
|
|
|
|
Less: |
|
|
|
|
|
|
|
Cash interest expense |
17,499 |
|
|
16,950 |
|
|
36,727 |
|
|
33,992 |
|
Development capital
expenditures(4) |
6,875 |
|
|
8,415 |
|
|
11,676 |
|
|
21,781 |
|
Distributions on Series A and
Series B preferred units |
— |
|
|
4,750 |
|
|
— |
|
|
9,500 |
|
Distributable
Cash Flow(3) |
$ |
15,276 |
|
|
$ |
39,820 |
|
|
$ |
20,341 |
|
|
$ |
66,641 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Minimum payments received in excess of
overriding royalties earned under a contractual agreement expiring
December 31, 2019. The remaining amount of the minimum payments is
recognized in net income.(2) Equity in EBITDA of equity method
investee is defined as the equity method investee's net income or
loss plus interest expense and depreciation. We divested our
interest in this investee in May of 2015.(3) Estimated maintenance
capital expenditures are intended to represent the amount of
capital required to fully offset declines in production, but do not
target specific levels of proved reserves to be achieved.
Estimated maintenance capital expenditures do not include the cost
of new oil and natural gas reserve acquisitions, but rather the
costs associated with converting proved developed non-producing,
proved undeveloped and unproved reserves to proved developed
producing reserves. These costs, which are incorporated in
our annual capital budget as approved by the Board, include
development drilling, recompletions, workovers and various other
procedures to generate new or improve existing production on both
operated and non-operated properties. Estimated maintenance
capital expenditures are based on management's judgment of various
factors including the long-term (generally 5-10 years) decline rate
of our current production and the projected productivity of our
total development capital expenditures. Actual production
decline rates and capital efficiency may materially differ from our
projections and such estimated maintenance capital expenditures may
not maintain our production. Further, because estimated
maintenance capital expenditures are not intended to target
specific levels of reserves, if we do not acquire new proved or
unproved reserves, our total reserves will decrease over time and
we would be unable to sustain production at current levels, which
could adversely affect our ability to pay a distribution at the
current level or at all.(4) Represents total capital
expenditures for the development of oil and natural gas properties
as presented on an accrual basis. For 2016, we intend to fund our
total oil and natural gas development program from net cash
provided by operating activities.
CONTACT:
Legacy Reserves LP
Dan Westcott
Executive Vice President and Chief Financial Officer
432-689-5200
Legacy Reserves Inc. (MM) (NASDAQ:LGCY)
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